In the process of rotary drilling a well, a drilling fluid or mud is circulated down the rotating drill pipe, through the bit, and up the annular space between the pipe and the formation or steel casing, to the surface. The drilling fluid performs different functions such as removal of cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when the circulation is interrupted, control subsurface pressure, isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, cool and lubricate the drill string and bit, maximize penetration rate etc.
The required functions can be achieved by a wide range of fluids composed of various combinations of solids, liquids and gases and classified according to the constitution of the continuous phase mainly in two groupings: aqueous drilling fluids, and oil based drilling fluids.
Aqueous fluids are the most commonly used drilling fluid type. The aqueous phase is made up of fresh water or, more often, of a brine. As discontinuous phase, they may contain gases, water-immiscible fluids such as diesel oil which form an oil-in-water emulsion, and solids including clays and weighting material such as barite. The properties are typically controlled by the addition of clay minerals, polymers and surfactants.
In drilling water-sensitive zones such as reactive shales, production formations, or where bottom hole temperature conditions are severe or where corrosion is a major problem, oil based drilling fluids are preferred. The continuous phase is typically a mineral or synthetic oil which may be alkenic, olefenic, esteric etc. Such fluids also commonly contain water or brine as discontinuous phase to form a water-in-oil or invert emulsion. Generally they furthermore contain a solid phase, which is essentially similar to that of aqueous fluids, and additives for the control of density, rheology and fluid loss. The invert emulsion is formed and stabilized with the aid of one or more specially selected emulsifiers.
Oil based drilling fluids also typically contain oil-soluble surfactants that facilitate the incorporation of water-wet clay or non-clay formation minerals, and hence enable such minerals to be transported to surface equipment for removal from circulation before the fluid returns to the drillpipe and the drillbit. The largest formation particles are rock cuttings, of size typically larger than 0.1-0.2 mm, removed by shale-shaker screens at the surface. Smaller particles, typically larger than about 5 μm, will pass through the screens, but can be removed by centrifuge.
Oil based drilling fluids have been used for many years, and their application is expected to increase, partly owing to their several advantages over water based drilling fluids, but also owing to their ability to be re-used and re-cycled, so minimizing their loss and their environmental impact.
As mentioned above, during drilling, formation particles become incorporated into the drilling fluid. Unless these are removed, they eventually move the fluid's properties, particularly the rheological parameters, out of the acceptable range. However, formation particles that are colloidal in size (less than about 5 μm) are more difficult to remove than the larger particles. A longer centrifuge run-time would be sufficient to remove the colloidal particles if the fluid were merely viscous, but the quiescent drilling fluid is usually required to behave as a gel to support cuttings in periods without circulation. Such a fluid will have a gel strength, and will behave as a non-Newtonian, shear-thinning fluid in which the viscosity at low shear rates is very large compared with the viscosity at the circulation rate.
Gel strengths typical of oil based fluids (1-10 Pa) can be shown to support particles of less than a few microns in size indefinitely against the centrifugal force typical of oilfield centrifuges, which then have no effect regardless of the time they run. Further, owing to their large specific surface area, colloidal-sized particles have a disproportionate effect on the rheology of a fluid. Moreover, as more colloidal particles become part of the fluid, the gel strength will generally increase. Thus as more colloidal particles are incorporated in the drilling fluid, the upper particle size that can be supported by the gel, and hence unremoved by the centrifuge, also increases. Increasing quantities of colloidal particles are detrimental to other aspects of a fluid's performance, particularly those engineering parameters important for efficient drilling.
Thus, in practice, the process of increasing colloidal concentration and decreasing treatment efficiency tends to continue until engineering parameters depart from their acceptable ranges. In particular, both the engineering rheology parameters plastic viscosity (PV) and yield point (YP) (API 1988) must be kept within bounds for efficient drilling. As drilling proceeds, and possibly also as the fluid is moved from one job to another, the driller can eventually find that PV and YP increase beyond their upper limits until the fluid becomes unusable for drilling and untreatable by centrifuge.
Typically PV should be in the range 20 to 100, and YP should lie between 15 to 55. Strictly, the PV and YP of drilling fluids are defined by the API-defined rheometer used to measure them, but they can be related to more generally used parameters by the Bingham Plastic rheology model in which the shear stress SS (in Pa) and shear rate SR (in reciprocal seconds or 1/s) are related by:SS=BYS+BPV×SR where BYS is the Bingham yield stress in Pa and BPV is the Bingham plastic viscosity in Pa s. The oilfield unit YP as measured by the API method is given by YP=1.96×BYS(Pa). Likewise, the oilfield unit PV=1000×BPV(Pa s).
Similar considerations apply to oil based completion fluids.